0000945764-12-000052.txt : 20121120 0000945764-12-000052.hdr.sgml : 20121120 20120620163821 ACCESSION NUMBER: 0000945764-12-000052 CONFORMED SUBMISSION TYPE: CORRESP PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 20120620 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DENBURY RESOURCES INC CENTRAL INDEX KEY: 0000945764 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752815171 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: CORRESP BUSINESS ADDRESS: STREET 1: 5320 LEGACY DRIVE CITY: PLANO STATE: TX ZIP: 75024 BUSINESS PHONE: 9726732000 MAIL ADDRESS: STREET 1: 5320 LEGACY DRIVE CITY: PLANO STATE: TX ZIP: 75024 FORMER COMPANY: FORMER CONFORMED NAME: NEWSCOPE RESOURCES LTD DATE OF NAME CHANGE: 19950627 CORRESP 1 filename1.htm correspondence.htm
 
 
June 20, 2012


Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 7010
100 F Street, N.E.
Washington, D.C.  20549

Attention:  Mr. Brad Skinner, Senior Assistant Chief Accountant

Re:         Denbury Resources Inc.
Form 10-K for Fiscal Year Ended December 31, 2011
Filed February 28, 2012
File No. 1-12935

Dear Mr. Skinner:

On behalf of Denbury Resources Inc. (the “Company” or “we”), set forth below are the Company’s responses to the comments of the Staff of the Securities and Exchange Commission regarding the above referenced filing as set forth in the Staff’s letter dated June 6, 2012.  For the Staff’s convenience, we have repeated each of the comments set forth in the Staff’s letter (in bold text) and followed each comment with the Company’s response (in normal text).


Form 10-K for Fiscal Year Ended December 31, 2011

Business and Properties - Oil and Natural Gas Operations, page 5

Rocky Mountain Region, page 13

Future Rocky Mountain Tertiary Properties without Proved Tertiary Reserves …, page 14

Grieve Field

1.  
We note the disclosure that you estimate that the Grieve project has the potential for recovery of approximately 12 MMBbls of gross oil, or 6.1 MMBbls net to your revenue interest. Explain to us what “potential for recovery” represents. Additionally, to the extent that this represents an estimate of oil or gas resources other than reserves, explain why you believe disclosure of these quantities is appropriate. See Instruction to Item 1202 of Regulation S-K.

Response:

The potential for recovery of approximately 12 million barrels (“MMBbls”) of gross oil, or 6.1 MMBbls net to our revenue interest, disclosed by us in our description of Grieve Field represents our estimate of probable oil reserves at that field.  In future Form 10-K and Form 10-Q filings, the Company will specifically describe the category of oil and gas reserves disclosed and, where probable reserves are included, will include the additional disclosure required by Item 1202(a)(5) of Regulation S-K.
 
 
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Estimated Net Quantities of Proved Oil and Natural Gas Reserves, page 21

2.  
Tell us the portion of proved undeveloped reserves at December 31, 2011 which are not currently scheduled to be drilled within five years of initial booking.  For any such quantities, describe the specific circumstances that justify reporting the quantities as proved undeveloped reserves.

Response:

The proved undeveloped reserves (“PUDs”) included in the Company’s December 31, 2011 reserve report that are not currently scheduled to be drilled within five years of initial booking total approximately 8,380 MBOE, which represents only 4.2% of the Company’s total proved undeveloped reserves and 1.8% of its total proved reserves at that date.

More than 99% of our PUDs that are scheduled for development more than five years from initial booking are proved undeveloped reserves which are part of CO2 enhanced oil recovery (“CO2 EOR”) projects.  As stated in our correspondence with the Staff dated April 16, 2010 in response to a previous request for information regarding the Company’s PUDs at December 31, 2009, we believe that these reserves satisfy the conditions of Rule 4-10(31)(ii) of Regulation S-X so as to fall within the “specific circumstances” exception of that rule.  Among the reasons that the development of these CO2 EOR projects meets the “specific circumstances” criteria, are the following:

·  
We have established and continue to follow the previously adopted development plan for each of these projects.  CO2 EOR projects are designed based on a variety of factors such as CO2 supply development, available CO2 volumes, maximizing rate of return, optimization of the CO2 recycle facility, capacity of the recycle facility, and other factors.  Once the development plan is established, it is difficult to alter the development of the field.  Because of these criteria, smaller fields tend to have shorter development periods and larger fields have longer development periods.  Large fields may have development periods in excess of ten years.  CO2 EOR projects where we have PUDs scheduled for development more than five years from initial booking were initiated between 2003 and 2008.  The Company has followed, and continues to follow, the development plans in each field with only minor adjustments since the initiation of each project.

·  
We have significant ongoing development activities in each of these CO2 EOR projects.  In each of these CO2 EOR projects, ongoing development activities include development drilling and reentering wells, including the conversion of certain wells to CO2 injection wells, installation of production flow lines, expansion of the facilities primarily for increasing the CO2 recycling capacities, and other necessary development work.  The Company has currently budgeted in excess of 61% of its 2012 capital expenditures (before acquisitions) for CO2-related activities, CO2 EOR production represented 47% of total production during 2011, and CO2 EOR reserves accounted for approximately 32% of Company proved reserves at December 31, 2011.  CO2 EOR is the Company’s core business strategy.

·  
We have a historical record of completing the development of comparable long-term projects. The Company has been developing CO2 EOR projects since 1999.  The Company currently owns and operates 16 active CO2 EOR projects.  None of the CO2 EOR PUDs recognized since 1999 associated with these long-term projects have experienced a downward revision because of the failure to develop the PUDs.  Over the past three years, the quantity of PUDs the Company has converted to proved developed reserves is seven times the quantity of PUDs at year-end 2011 which are not currently scheduled to be drilled within five years of initial booking.
 
 
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3.  
Provide us, as supplemental information, a schedule that shows, for the years included in your filing, the following regarding your proved undeveloped (PUD) reserves:

·  
PUD reserves at the beginning of the year;

·  
PUD reserves added during the year;

·  
PUD reserves converted to PD reserves during the year;

·  
Other changes in PUD reserves;

·  
PUD reserves at the end of the year;

·  
Total estimated future development costs at the beginning of the year; and,

·  
Actual development costs incurred during the year.

Provide the quantity information separately for oil and gas and on a combined BOE basis.

Response:

The following tables set forth information regarding proved undeveloped reserves:

Estimated Quantities and Development Costs for Proved Undeveloped Reserves (dollars in millions):

   
2011
  
 
  
Oil
(MBbls)
    
Natural Gas
(MMcf)
    
Total
(MBOE)
  
PUD reserves at the beginning of the year
     119,199       247,377       160,428  
PUD reserves added during the year
     34,847       42,550       41,939  
PUD reserves acquired during the year
     4       237,191       39,536  
PUD reserves sold during the year
     —       —       —  
PUD reserves converted during the year
     (32,590 )     (11,930 )     (34,578 )
Other changes in PUD reserves
     (3,468 )     (15,950 )     (6,127 )
PUD reserves at the end of the year
     117,992       499,238       201,198  
 
                        
Total estimated future PUD development costs at the beginning of the year 1
     $ 1,651  
PUD development costs incurred during the year
     $ 516  

1
Represents estimated future development costs to be incurred on PUDs as included in our December 31, 2010 reserve report.
 
 
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2010
  
 
  
Oil
(MBbls)
    
Natural Gas
(MMcf)
    
Total
(MBOE)
  
PUD reserves at the beginning of the year
     76,687       18,462       79,765  
PUD reserves added during the year
     47,724       103,137       64,914  
PUD reserves acquired during the year
     23,886       281,569       70,814  
PUD reserves sold during the year
     (8,244 )     (153,566 )     (33,838 )
PUD reserves converted during the year
     (19,402 )     (3,550 )     (19,994 )
Other changes in PUD reserves
     (1,452 )     1,325       (1,233 )
PUD reserves at the end of the year
     119,199       247,377       160,428  
 
                        
Total estimated future PUD development costs at the beginning of the year 2
     $ 647  
PUD development costs incurred during the year
     $ 248  

2
Represents estimated future development costs to be incurred on PUDs as included in our December 31, 2009 reserve report.


 
  
2009
  
 
  
Oil
(MBbls)
    
Natural Gas
(MMcf)
    
Total
(MBOE)
  
PUD reserves at the beginning of the year
     82,380       129,841       104,020  
PUD reserves added during the year
     9,897       4,259       10,607  
PUD reserves acquired during the year
     692       —       692  
PUD reserves sold during the year
     (7,856 )     (115,390 )     (27,088 )
PUD reserves converted during the year
     (4,898 )     —       (4,898 )
Other changes in PUD reserves
     (3,528 )     (248 )     (3,568 )
PUD reserves at the end of the year
     76,687       18,462       79,765  
 
                        
Total estimated future PUD development costs at the beginning of the year 3
     $ 762  
PUD development costs incurred during the year
     $ 135  

3
Represents estimated future development costs to be incurred on PUDs as included in our December 31, 2008 reserve report.


Financial statements, page 59

Notes to consolidated financial statements, page 67

Note 15. Supplemental Oil and Natural Gas Disclosures, page 94

Estimated quantities of reserves, page 95

4.  
Disclosure elsewhere in your filing indicates that your oil and gas reserves include quantities of natural gas liquids. In view of this, explain to us how you have considered the disclosure requirements of FAS ASC paragraph 932-235-50-4(a). If you have concluded that natural gas liquids are not significant, provide us with an analysis that supports your conclusion.
 
 
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Response:

Estimated proved crude oil reserves at December 31, 2011, including proved condensate and natural gas liquids reserves, totaled 357.7 MMBbls.  Proved natural gas liquids reserves constituted 1.2 MMBbls, or 0.3% of both proved crude oil and total proved reserves.   The Company considered FAS ASC paragraph 932-235-50-4(a) and concluded the natural gas liquids reserves were inconsequential and not appropriate for separate disclosure.  We believe our current disclosure to be in compliance with the FASB requirements, and no additional disclosure is considered necessary.
 
 
In connection with the foregoing responses, the undersigned, on behalf of the Company, acknowledges that:

·  
The Company is responsible for the adequacy and accuracy of the disclosure in the filing;
·  
Staff comments or changes to disclosures in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and
·  
The Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Thank you for your time and consideration of this matter.  If you have any questions or concerns about this response, please contact the undersigned at 972-673-2007, or by fax at 972-673-2150.

Sincerely,

/s/ Mark C. Allen

Mark C. Allen
Sr. Vice President and Chief Financial Officer
 
 
 
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